The present invention generally relates to telemetering downhole sensor information while conducting operations in an oil or gas well using coiled tubing. More particularly, it relates to transmission of downhole sensor data during a coiled-tubing hydraulic fracturing operation such that the data can be processed at the surface to assess downhole conditions and further used to optimize the fracturing operation.
An oilfield hydraulic fracturing process involves subjecting a geologic formation to hydraulic pressure, typically using a specialized fracturing fluid that includes particulate material referred to as proppant. The fracturing fluid is typically pumped down a tubing string made either of jointed pipe sections or continuous coiled tubing. The present invention pertains particularly to a coiled tubing conduit as opposed to a string of jointed pipe. The fracturing treatment results in the development of a series of fractures in the formation which enhance extraction of hydrocarbons from the formation.
Such treatment processes have been designed and modified based on measurement of hydraulic pressure at the surface. Numerical models utilize the surface pressure measurements to extrapolate the annular pressure at the fracture zone in designing the proppant volume in the fluid; however, actual downhole memory gauge measurements have indicated that the extrapolated pressures can vastly differ from the measured annular pressures at the fractured zone. Differences in extrapolated measurements from actual annular pressures can result in either longer treatment periods or inefficient treatment. Real-time access to actual annular pressure data could significantly improve and optimize the treatment process.
At present, wireless methods of transmitting downhole sensor data are not commercially available for coiled tubing delivered services. The industry has investigated e-line or e-coiled tubing (that is, electrical transmission along wire or coiled tubing) to access this important data. However, attempts to do so have had problems due to interference of the fracturing fluid flow with the e-line and the harsh nature of the fluid and proppants that have damaged the e-line. Mud pulse telemetry is a known technique, but its rates are slower than the minimum required for the fracturing job pressure data transmission application referred to above, for example. The mud pulse telemetry pulser also wears quickly due to the abrasive proppant flowing through it. In addition, pressure pulses may interfere with critical pressure measurements. Electromagnetic (EM) telemetry has been considered for coiled tubing services, but its data rate is lower than the minimum required for the application. EM signals also encounter high attenuation in regions of low formation resistivity, in cased holes, and where borehole fluid is highly conductive. Regarding acoustic telemetry, Halliburton has developed and commercialized an acoustic telemetry system (ATS) designed to operate on jointed pipe. The acoustic transmission channel characteristics of jointed pipe include frequency banding due to reflections at tool joints. The ATS system employs modified FSK telemetry to overcome the transmission channel characteristics. There is presently no commercial wireless method to transmit sensor data from downhole during coiled tubing delivered services.
It is apparent from the foregoing that there is a need for a wireless telemetry system that is capable of transmitting real-time sensor data to the surface during coiled tubing delivered services. In addition, the telemetry system needs to function in a corrosive and abrasive environment, such as encountered during fracturing a subterranean formation, for example.